The treatment of natural gas for the removal of CO.sub.2 typically requires the processing of large volumes of gas to produce a treated gas product with about a 1 to about 4 mol % CO.sub.2. The CO.sub.2 is removed from natural gas for reasons such as improving the heating value of the treated gas for pipeline transmission and, recovering the CO.sub.2 from gases associated with oil field CO.sub.2 injection for enhanced oil production.
The properties which permit CO.sub.2 to be separated from other gases such as hydrocarbons, CO, N.sub.2 and air are as follows: weak acidity when dissolved in water, permitting the use of liquid alkaline solutions for absorption of CO.sub.2 ; solubility in water and organic liquids, permitting processes based on solubility rather than chemical affinity; molecular size and structure, permitting the selective adsorption on solid adsorbents, such as molecular sieves; and acidic nature and size and structure, permitting the use of permeable membranes for separation.
Natural gas is a general term which is applied to mixtures of inert and light hydrocarbon components which are derived from natural gas wells or from gas associated with the production of oil. Typically, the quality of the natural gas, as produced, will vary according to the content and amount of inert gases and other impurities in the natural gas. These inert gases such as nitrogen, carbon dioxide, and helium will reduce the heating value of the natural gas. Because natural gas is usually saturated with water, the presence of carbon dioxide in significant amounts may make the natural gas corrosive. Natural gas is conveyed from its source to the consumer in pipelines. As a result, very rigid guidelines have been established by the gas transmission industry to maintain a high quality, safe product. Typical specification for pipeline quality natural gas include: Nitr ogen less than 4%, and Carbon dioxide less than 4%.
The most important aspect of any process for treating natural gas is economics. The most critical characteristics of a CO.sub.2, removal process are its energy requirements and the concentration level to which CO.sub.2 can be lowered in the exit gas. Natural gas is treated in very high volumes making even slight differences of 1-2% in the capital or operating cost of the treating units very significant factors in the selection of process technology. Furthermore, because natural gas is a potentially dangerous and explosive fuel, processes are sought which have high reliability and represent a simplicity of operation.
Absorption systems are commonly used for the removal of CO.sub.2 from the natural gas. A physical solvent such as a dimethylether of polyethylene glycol or chemical solvents such as alkanolamines or alkali metal salts are used to wash out carbon dioxide. The CO.sub.2 rich solvent is subsequently regenerated by stripping of CO.sub.2 with heat. Alkanolamines are not only useful in absorbing carbon dioxide, but they have also been employed to absorb hydrogen sulfide or carbonyl sulfide from gas mixtures which may or may not contain carbon dioxide. Alkanolamines are classified as primary, secondary, or tertiary depending on the number of nonhydrogen substituents bonded to the nitrogen atom of the amino group. Monoethanolamine is an example of a well-known primary alkanolamine. Conventionally used secondary alkanolamines include diethanolamine and diisopropanolamine. Triethanolamine and methyldiethanolamine are examples of tertiary alkanolamines which have been used to absorb carbon dioxide from industrial gas mixtures.
After absorption of carbon dioxide and/or hydrogen sulfide and/or carbonyl sulfide in an alkanolamine solution, the solution is regenerated to remove absorbed gases. The regenerated alkanolamine solution can then be recycled for further absorption. Absorption and regeneration are usually carried out in different separatory columns containing packing or bubble plates for efficient operation. Regeneration is generally achieved in two stages. First, the absorbent solution's pressure is reduced so that absorbed carbon dioxide is vaporized from the solution in one or more flash regenerating columns. Next, the flashed absorbent is stripped with steam in a stripping regenerating column to remove residual absorbed carbon dioxide.
Alkali metal salts such as carbonates, phosphates, borates, phenates of sodium and potassium represent another category of absorbent liquid. The carbon dioxide absorption rates of such salts is, however, rather low, and, therefore, it has been necessary to add promoting agents to these salts. For example, an article by Sartori et al., entitled "Sterically Hindered Amines for CO.sub.2 Removal from Gases", Industrial Engineering Chemical Fundamentals, Vol. 22, pp. 239-49 (1983) ("Sartori article") discloses activating a basic salt for removing carbon dioxide from gaseous mixtures with sterically hindered amines or amino acids (i.e., a primary amine in which the amino group is attached to a tertiary carbon atom or a secondary amine in which the amino group is attached to a secondary or tertiary carbon atom). Primary and secondary alkanolamines undergo a fast direct reaction with carbon dioxide. However, considerable heat is required to break the bond between the alkanolamine and carbon dioxide in order to regenerate the absorbent. Because tertiary alkanolamines do not bond with carbon dioxide, they can be economically regenerated often by simply reducing pressure in the system (i.e, flash regenerating); little or no thermal regeneration is required. Although the absence of a direct reaction with carbon dioxide makes regeneration of tertiary alkanolamines more economical, large solvent circulation rates and high liquid to gas ratios (i.e., high liquid loadings) in the absorber are required due to the slow absorption of carbon dioxide. Consequently, systems utilizing tertiary alkanolamines require absorption columns of increased height and diameter compared to systems employing either primary or secondary alkanolamines. Typically, the use of either an alkali metal salt absorbent or an alkanolamine absorbent based wet-scrubbing process requires the use of a further dehydration step employing a glycol to dry the gas. Processes are sought which do not require significant amounts of heat for regeneration and which do not require the additional processing step of water removal.
Membranes such as those disclosed in U.S. Pat. No. 4,230,463 to Henis et al. are effective for separating at least one gas component from a gaseous mixture by permeation wherein the membranes are comprised of a coating in occluding contact with a porous separation membrane. Membranes may be used in a single stage or integrated in multiple stages to preferentially separate the more permeable component. However, the membranes will pass a portion of the less permeable gases along with the preferentially separated gas thereby limiting recovery of the non-permeable gases and producing a low quality permeate reject stream. As a result of this limitation, single stages of membranes are often combined with additional membrane stages and recycle of the permeate with the feed to the first stage to improve the separation and reduce losses. However, the additional membrane stages combined with the added recompression costs to recompress the permeate stream and recycle it to the first membrane stage are significant as membranes do not provide any economy of scale with increases in gas capacity for the same separation. The cost of membrane technology is directly proportional to the area of the membrane employed. U.S. Pat. No. 4,130,403 to Cooley et at. is an example of the use of multiple stages of membrane separation to obtain a carbon dioxide-rich permeating gas.
Alternatively carbon dioxide can be rejected from a multiple component gas stream comprising methane and carbon dioxide in a pressure swing adsorption (PSA) system by recovering high purity methane product and rejecting the tail gas comprising carbon dioxide. However, the PSA process doesn't operate efficiently at the pressures at which the natural gas is available, requiting all of the gas feed to the PSA unit to be reduced to a lower adsorption pressure and all of the treated gas to be recompressed to the product gas pressure.
U.S. Pat. No. 4,229,188 discloses a process which combines a PSA and a membrane system to produce a high purity product essentially of a single gas. High purity hydrogen is recovered from a feed gas mixture containing hydrogen by passing the feed gas mixture to a selective adsorption unit to initially separate the hydrogen gas. The low pressure tail gas from the PSA is further treated by a membrane system to recover additional quantity of hydrogen. Alternatively and as taught in U.S. Pat. Nos. 4,398,926 and 4,701,187, the feed gas mixture may initially be separated in a membrane separation unit to provide bulk separation of hydrogen. The separated hydrogen may then be passed to a PSA unit to achieve high purity hydrogen gas at high recovery. In U.S. Pat. No. 4,701,187, the tail gas purge stream from the PSA adsorption unit is compressed and recycled with the feed gas mixture to the membrane unit to form an efficient system.
In U.S. Pat. No. 4,863,492 a gas permeable membrane is combined with a PSA unit to produce a mixed gas product having a preset, adjustably-controlled gas ratio and a high purity second gas component. The permeate stream from the gas permeable membrane is fed to the PSA unit and the taft gas from the PSA unit is compressed and blended with the non-permeate steam to form the mixed gas product.
Membranes have been combined with PSA units to improve the recovery of light components. For example, U.S. Pat. No. 4,238,204 to Perry relates to a selective adsorption process for the recovery of a light gas, especially hydrogen, from a feed gas mixture by using a membrane permeator unit selectively permeable to the light gas to recover a more concentrated light gas from a stream comprising the light gas. The light gas is used to regenerate a selective adsorber unit. The more concentrated light gas is utilized in the selective adsorber unit, either blended with the feed gas mixture, or as a purging gas to improve the recovery of the highly purified light gas product.
U.S. Pat. No. 4,398,926 to Doshi relates to a process for recovery of hydrogen from a gas stream containing hydrogen and impurities. The process achieves the bulk separation of hydrogen from the gas stream in a membrane unit and then separates the hydrogen from the impurities in a PSA unit to produce a purified hydrogen product and a waste gas stream. A high pressure gas stream having a hydrogen content up to 90 mol % is passed to a permeable membrane capable of selectively permeating hydrogen. The separated hydrogen is recovered at reduced pressure and passed to a PSA unit adapted for operation at the reduced pressure. The non-permeate comprising hydrogen from the permeable membrane is recovered essentially at the higher pressure of the gas stream. A portion of the non-permeate is throttled to a lower pressure with appropriate power recovery and is passed to the PSA unit as a co-feed gas. The co-feed gas contributes to the recovery of the purified hydrogen product and a reduction in the operating costs for the desired hydrogen separation and purification.
Membrane and pressure swing adsorption (PSA) processes are safe and simple systems to operate. As dry systems, membrane and PSA processes, are less susceptible to corrosion and other operating problems associated with wet, amine based carbon dioxide removal systems. However, multistage membrane systems require large amounts of compression for efficient operation, which can represent large capital and energy costs. On the other hand, PSA systems are relatively inefficient at high pressures typically encountered in natural gas treating processes.
It is an objective of the invention to develop a simple dry process incorporating efficient use of the membrane and pressure swing processes to produce a natural gas depleted in carbon dioxide, at a high pressure with a minimum requirement of the gas compression.
It is a further object of the invention to provide a low cost, energy efficient process for the separation of carbon dioxide from a natural gas stream without the need for additional processes to remove water from the product natural gas